Subterranean drilling typically involves rotating a drill bit from surface or on a downhole motor at the remote end of a tubular drill string. It involves pumping a drilling fluid down the inside of the tubular drillstring, through the drill bit, and circulating this fluid continuously back to surface via the drilled space between the hole/tubular, referred to as the annulus. This pumping mechanism is provided by positive displacement pumps that are connected to a manifold which connects to the drillstring, and the rate of flow into the drillstring depends on the speed of these pumps. The drillstring is comprised of sections of tubular joints connected end to end, and their respective outside diameter depends on the geometry of the hole being drilled and their effect on the fluid hydraulics in the wellbore. The drillstring ends are connected by a thicker material larger diameter section of the joint located at both ends of the section called tool joints.
Tool joints provide high-strength, high pressure threaded connections that are sufficiently robust to survive the rigors of drilling and numerous cycles of tightening and loosening at the drillpipe connections. The large diameter section of the tool joints provides a low stress area where rig pipe tongs are used to grip the pipe to either make up or break apart the connection of two separate sections of drillpipe.
For a subsea well bore, a tubular, known as a riser extends from the rig to a well head at the top of the wellbore subsea on the ocean floor. It provides a continuous pathway for the drill string and the fluids emanating from the well bore. In effect, the riser extends the wellbore from the sea bed to the rig, and the annulus also comprises the annular space between the outer diameter of the drill string and the riser.
The bit penetrates its way through layers of underground formations until it reaches target prospects—rocks which contain hydrocarbons at a given temperature and pressure. These hydrocarbons are contained within the pore space of the rock i.e. the void space and can contain water, oil, and gas constituents—referred to as reservoirs. Due to overburden forces from layers of rock above, these reservoir fluids are contained and trapped within the pore space at a known or unknown pressure, referred to as pore pressure. An unplanned inflow of these reservoir fluids is well known in the art, and is referred to as a formation influx or kick and commonly called a well control incident or event.
The purpose of the drilling fluid (also known as mud) is to lubricate, carry drilled rock cuttings to surface, cool the drill bit, and power the downhole motor and other tools. Mud is a very broad term and in this context it is used to describe any fluid or fluid mixture that covers a broad spectrum from air, nitrogen, misted fluids in air or nitrogen, foamed fluids with air or nitrogen, aerated or nitrified fluids, to heavily weighted mixtures of oil and water with solids particles. Most importantly this fluid and its resulting hydrostatic pressure—the pressure that it exerts at the bottom of the well bore (known as the bottom hole pressure or BHP) from its given density and total vertical height/depth—prevent the reservoir fluids at their existing pore pressure from entering the drilled annulus. The drilling fluid must also exert a pressure less than the fracture pressure of the formation, otherwise fluid will be forced into the rock as a result of pressure in the wellbore exceeding the formation's horizontal stress forces.
The BHP exerted by the hydrostatic pressure of the drilling fluid is the primary barrier for preventing influx from the formation. BHP can be expressed in terms of static BHP or dynamic/circulating BHP. Static BHP relates to the BHP value when the mud pumps are not in operation. Dynamic or circulating BHP refers to the BHP value when the pumps are in operation during drilling or circulating.
The use of blow out preventers, referred to as BOP's, are used to seal and control the formation influxes, described herein, in the wellbore are well known in the art—these are compulsory pressure safety equipment used on both land and off-shore rigs. Whilst land and subsea BOPs are generally secured to the well head at the top of a wellbore, BOPs on off-shore rigs are generally mounted subsea and below the rig deck and integrated into the riser system and positioned on the ocean floor. These are well known in the art.
The annular BOP elements seal around the drill string, thus closing the annulus and stopping flow of fluid from the wellbore. They typically include a large flexible rubber or elastomer packing unit configured to seal around a variety of drillstring sizes when activated, and are not designed to be actuated during drillstring rotation as this would rapidly wear out the sealing element. A pressurized hydraulic fluid and piston assembly are used to provide the necessary closing pressure of the sealing element. With wellbore pressure below the closed element some fluid may invade the sealing face from below and assist in lubricating the pipe as it is moved through the element—but this is not a controlled process. With these conditions, when a continuous leak rate occurs through a BOP it generally indicates a loss of integrity. These are well known in the art.
Managed Pressure Drilling (MPD) and/or Underbalanced Drilling (UBD) utilizes additional special equipment that has been developed to keep the well closed at all times, as the wellhead pressures in these cases are above atmospheric pressure, unlike in conventional overbalanced drilling. MPD generally allows drilling with a pressurized annulus while preventing co-mingled and/or produced formation fluids hydrocarbons from entering the wellbore and reaching surface, resulting in a pressurized annulus of a single density drilling fluid. UBD allows the flow of comingled drilling and reservoir fluids to surface during drilling and therefore contains a pressurized annulus containing hydrocarbons and drilling fluid which may be multi-phase.
Equivalent circulating density—ECD is the increase in the BHP expressed as an increase in pressure that occurs only when drilling fluid is being circulated. The ECD value reflects the total friction losses over the entire length of the wellbore annulus, from the point of fluid exiting the drilling bit at the wellbore bottom to where it exits the well at the surface just below the rig floor of the floating installation. The ECD can result in a bottom hole pressure during circulating/drilling that varies from slightly to significantly higher values when compared to static conditions i.e. no circulation. Therefore the goal of a conventional drilling system is to maintain the BHP above the pore pressure but below the fracture pressure while taking the ECD into account to manage the BHP. The management of BHP through MPD allows the BHP to be controlled and maintained as constant as possible within a narrow window using a combination of a lighter drilling fluid and applied choke pressure at surface.
During MPD and/or UBD, the closed loop is generated by a pressure seal around the drillpipe at surface with a rotating pressure containment device—RPC, and flow is diverted to a flow line below the sealing point of this device. These sealing devices can also be referred to as a Rotating Control Device—RCD or Rotating Control head—RCH, Rotating Blowout Preventer—RBOP, or Pressure Control While Drilling—PCWD. The function of the RPC device is to allow the drill string and its tool joints to pass through while reciprocating/stripping or rotating while maintaining pressure integrity such that the annulus isolated from the external atmosphere. All the aforementioned devices use a stationary seal that does not rotate relative to the drill pipe and the rotation is handled by a bearing which may be a thrust, roller, cone or ball bearing(s) or a combination of these.
Stripping is the vertical movement of drill pipe through any sealing device with wellbore pressure present below the sealing point. As both the frequency of larger diameter tool joints passing through the element and the velocity of the pipe movement increase during stripping, this is generally when most sealing devices tend to fail. These two main factors in combination with temperature and wellbore fluid composition result in the operational longevity of the sealing device to be affected.
A typical RPC device includes an elastomer or rubber packing/sealing element and a bearing assembly that allows the sealing element to rotate along with the drill string. There is no rotational movement between the drill string and the sealing element—only the bearing assembly exhibits the rotational movement during drilling. These are well known in the art and are described in detail in U.S. Pat. Nos. 7,699,109, 7,926,560, and 6,129,152.
The pressure seal provided by conventional RPC designs is achieved using active and/or passive methods.
Passive sealing is accomplished by the exertion from the wellbore pressure below against the lower part of the sealing element exposed to the annulus which forces the element inwards against the drill pipe external surface. Passive seals are well known in the art and are described in U.S. Pat. No. 7,040,394.
Active seals are usually provided by the use of a hydraulics network system, circuitry, and bladder. A hydraulic circuit provides fluid to the RPC device and a high pressure hydraulic pump within the circuit is used to energize the active seal arrangement. The pressure chamber for activating the bladder is preferably defined within the rotating seal assembly, and the rotating seal assembly includes both the bladder and the bearings. The rotating seal assembly is hydraulically secured within the RPC device housing, usually by remote control and performed by a single cylindrical latch piston. Active seals are well known in the art, and disclosed, for example, in U.S. Pat. Nos. 7,380,590 and 7,040,394.
Current systems and methods associated with these prior art pressure containment devices allow for a controlled lubrication across their active or passive sealing mechanism that consists of a lubrication fluid, usually oil. The oil is contained under pressure within the bearings by the use of special seals that allow for the isolation of the pressurized bearing from the wellbore fluids. Any leak of wellbore fluids across these seals will result in failure of the seals due to the abrasive action of the mud containing drill cuttings and subsequent rapid failure of the bearings or bearing assembly.
During times of circulating and non-circulating it is critical that the BHP at the bottom of the hole where the reservoir exists is always greater than the reservoir pressure. During connections, where additional pipe must be added, the BHP must be maintained during periods of no circulation through the drilling bit. During MPD and in the absence of continuous circulation methods as disclosed in U.S. Pat. No. 2,158,356, an external high volume pump is used to inject fluid into the riser at a point below the RPC device. This injected fluid circulates through to the main returns flow line at surface and through the choke valve, such that a combination of the choke position and/or injected flow rate can be used to maintain the BHP constant during connections.
There are inherent problems related to the design of current RPC technology. It is difficult to monitor the wear or integrity of the sealing element in question when it is in service, and depending on the axial and radial loads and bending moments present from drilling the internal sealing face between the drillpipe and sealing element starts to wear. Furthermore, bearing assemblies and internal seals under excessive drilling loads start to mechanically fail. However, with dual sealing arrangements differential pressure across the lower sealing element may be monitored in the cavity between the upper and lower sealing elements to determine if the wellbore pressure is passing the lower seal. Such a system is described in US 2013/0118749. Additionally, with these designs there are no lubricating fluids injected or pumped across the sealing faces to reduce the friction and heat generated from pipe movement through the seal during stripping or drilling.
The loads imposed on the sealing elements of any RPC device increase as larger diameter tool joints pass through the sealing assembly, resulting in a higher degree of deformation and imposing higher axial and compressive loads on the sealing elements. During stripping operations, where excessive lengths of drill pipe are reciprocated in or out of the well with wellbore pressure present below the RPC device, multiple tool joints pass through the sealing element causing it to wear and permanently deform over time.
The degree of deformation and wear depends on the magnitude of the wellbore pressure, temperature, fluid composition, and upward/downward velocity of the pipe through the element. The higher the wellbore pressure, the higher the differential pressure is created across the sealing face. Higher temperatures and different fluid compositions further degrade the sealing element, affecting its performance and causing further breakdown. Furthermore, as the sealing elements deform, solids from the wellbore invade the sealing face which increases the wear rate. Without a lubricating fluid the wear rates on typical RPC designs can be excessive, and without the ability to accurately monitor the integrity of the sealing element in question the sealing elements tend to suddenly fail before they can be replaced. This can result in the uncontrolled release of fluid and/or gas pressure at the rig floor and to the surrounding atmosphere.
Additionally, the frictional coefficients present with elastomeric materials used in current RPC sealing element designs are too high and greatly affect their operational life. This, compounded with the problems described herein, impacts the effectiveness of their sealing capacity.
A new design approach to pressure containment technology was described in previously filed patent applications WO2012/127227 and WO2011/128690.
The system design and methods disclosed in these applications includes a tubular elastomeric or polymeric stripping sleeve inserted and concentrically positioned across an annular packing unit. As the packer closes, the radial pressure of the packer on the external surface of the sleeve forces it radially inwards against the tubular, thus providing a non-rotating seal for drillpipe rotation i.e. the drillpipe rotates within the stationary sleeve. This system uses no conventional bearings, and the radial friction created from the annular packer against the external surface of the sleeve prevents the sleeve from rotating with the drill pipe. The stripping sleeve sustains the integrity of the annular packer and becomes the wearable, disposable item.
In a stacked dual configuration i.e. two sleeves and two annular packers spaced a specific distance apart, the wellbore pressure can be staged down across each sealing face to reduce the overall pressure drop and further enhance longevity. The dual assembly allows the staging of larger diameter tool joints if spaced adequately apart, eliminating the larger tool joint diameter from being forced upwards or downwards into the closed sleeve. This would further enhance its longevity as the sleeve would not be exposed to the additional loads imposed by the tool joint body.
A set of upper and lower locking dogs/pistons contained within the annular packer housing allow the landing and securing of either a single or dual sleeve arrangement. These extend radially inwards into the central bore of the housing and prevent longitudinal movement of the stripping sleeve.
In the dual arrangement, fluid is injected between the two energized sleeves and maintained at a specified pressure determined by the wellbore pressure present. The fluid is returned through a return line opposite the injection line, equipped with a choke such that pressure between the sleeves can be controlled. Maintaining this pressure within the cavity decreases the pressure drop across the lower sleeve and enhances the sleeve's longevity as a result. Furthermore, the opposing fluid rates from the return and injection lines can be compared to determine the integrity of the sleeves—i.e. if fluid is either passing through the upper or lower sleeve or if wellbore fluid is entering passing through the lower sleeve. Supplying a lubricating fluid to this cavity may assist in lubricating the drill string as it enters this region and thus ultimately reducing the frictional forces between the sealing faces of the sleeve and the drill pipe. The lubrication fluid does not have to be a special lubricant or oil as for the bearing type systems mentioned earlier. It is sufficient for this to consist of ‘clean’ drilling fluid i.e. drilling fluid which has had the cuttings removed. Such fluid is in ample supply from the active drilling tank which is the same supply as is pumped down the drill pipe.
This design may also provide a floating fluid seal or hydrodynamic film between the seal sleeve and the drill string that will assist in actively sealing around the tubular, using lubricants such as drilling fluid or hydraulic oil. This may assist in decreasing friction and associated wear rates as the drill pipe is rotated and reciprocated through the energized sleeve.